Current methods for completing hydrocarbon wells often involve isolating zones of interest using packers, cement and the like, and pumping fracturing fluids into the wellbore to stimulate one or more production zones of a well. For example, the casing of a cased wellbore may be perforated to allow oil and/or gas to enter the wellbore and fracturing fluid may be pumped into the wellbore through the perforations into the formation. For open uncased wellbores, stimulation may be carried out directly in the zones. The downhole completion equipment may use downhole tools such as ball-actuated frac sleeves, which may be arranged in series. The frac sleeves have side ports that block fluid access to a production zone with which it is associated until an appropriately sized ball is pumped down from the surface to open the sleeve. The ball lands on a ball seat in the ball-actuated frac sleeve and frac fluid pressure on the ball forces the side ports in the frac sleeve to open and provide fluid access to that production zone. Other types of fracing operations, and other ball actuated downhole devices are well known in the art.
This process of hydraulic fracturing (“fracing”) creates hydraulic fractures in rocks, with a goal to increase the output of a well. The hydraulic fracture is formed by pumping a fracturing fluid into the wellbore at a rate sufficient to increase the pressure downhole to a value in excess of the fracture gradient of the formation rock. The fracture fluid can be any number of fluids, ranging from water to gels, foams, nitrogen, carbon dioxide, or air in some cases. The pressure causes the formation to crack, allowing the fracturing fluid to enter and extend the crack further into the formation. To maintain the fractures open after injection stops, propping agents are introduced into the fracturing fluid and pumped into the fractures to extend the breaks and pack them with proppants, or small spheres generally composed of quartz sand grains, ceramic spheres, or aluminum oxide pellets. The propped hydraulic fracture provides a high permeability conduit through which the formation fluids can flow to the well.
At the surface, hydraulic fracturing equipment for oil and natural gas fields usually includes frac tanks holding fracturing fluids and which are coupled through supply lines to a slurry blender, one or more high-pressure fracturing pumps to pump the fracturing fluid to the frac head of the well, and a monitoring unit. Fracturing equipment operates over a range of high pressures and injection rates. Many frac pumps are typically used at any given time to maintain the very high, required flow rates into the frac head and into the well.
An industry standard prior art fracturing tree (“frac tree”) is typically mounted vertically above a wellhead and includes the frac head, sometimes termed a “pump block” or a “goat head”, which is a large block of steel for injecting frac fluids. Since the frac head is mounted above the wellhead, it may be at an elevation of about 14-16 feet (about 5 meters) from the ground. The frac head includes multiple fluid inlets which are connected to supply lines to allow frac fluids to be combined from multiple supply lines into the central bore of the frac head. The combined flow of frac fluids is pumped under pressure downwardly through a bottom outlet of the frac tree into the central bore of the wellhead. Generally, the frac tree includes one or more master valves below the frac head, and above the bottom outlet. An axial passageway extends through the frac tree from the central bore of the frac head through the master valves to the bottom outlet. The axial passageway is generally a radial bore to accommodate radial balls being launched through the frac tree. A flow back tee, is typically a standard component of a frac tree. The flow back tee accommodates fluids flowing back through the frac tree for diversion through the one or more valved side arms. For instance, a ball catch device may be connected to one of the side arms for balls being returned from the wellbore through the wellhead.
To stimulate multiple zones in a single stimulation treatment, a series of packers in a packer arrangement is inserted into the wellbore, each of the packers being located at intervals for isolating one zone from an adjacent zone. A ball is introduced from the frac tree into the wellbore to selectively engage one of the packers in order to block fluid flow therethrough, permitting creation of an isolated zone uphole from the packer for subsequent treatment or stimulation. Once the isolated zone has been stimulated, a subsequent ball is dropped to engage a subsequent packer, above of the previously engaged packer, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Typically the balls range in diameter from a smallest ball, suitable to engage the most distant packer, to the largest diameter, suitable for engaging the packer located most proximate the surface. Other stimulating methods are known which involve dropping repeater balls of same or similar size.
Although the balls can theoretically be dropped through a surface valve, this is a slow process that is dangerous to operators if a mistake is made. Consequently, ball launch mechanisms for dropping or injecting balls sequentially in an appropriate size sequence into a frac fluid stream have been designed. However, such mechanisms are often subject to mechanical failure and/or operator error. As is well understood, a ball dropped out of sequence is undesirable because one or more zones are not fractured and the ball-actuated sleeves associated with those zones are left closed, so expensive remediation is required.
U.S. Pat. No. 8,636,055 issued Jan. 28, 2014 to Young et al., describes a ball drop system in which the balls are arranged vertically, on above another, with the smallest at the bottom and the largest at the top of a ball cartridge that is mounted above the frac head. The ball cartridge houses a ball rail having a bottom end that forms an aperture with an inner periphery of the ball cartridge through which balls of a ball stack supported by the ball rail are sequentially dropped from the ball stack as a size of the aperture is increased by an aperture controller operatively connected to the ball rail. Depending on the number of balls needed for a system, this ball drop system adds excessive height to the overall frac tree, raising safety issues and making it difficult and costly to service and install. As well, when exposed to the high pressures of the frac tree system, and coupled with the extreme freezing temperatures during use, the balls may fail to release when the aperture is opened.
When operational problems occur, such as malfunctioning valves or balls becoming stuck and not being pumped downhole, these problems may result in failed well treatment operations, requiring costly and inefficient re-working. At times re-working or re-stimulating of a well formation following an unsuccessful stimulation treatment may not be successful, resulting in a production loss.
Another technique to introduce balls involves an array of remote valves positioned onto a multi-port connection at the wellhead with a single ball positioned behind each valve. Each valve requires a separate manifold fluid pumper line and precise coordination both to ensure the ball is deployed and to ensure each ball is deployed at the right time in the sequence, throughout the stimulation operation. The multi-port arrangement requires multiple high pressure valves and other equipment, increasing the capital costs for the frac operation. The multiplicity of high pressure lines also logistically limits the number of balls that can be dropped due to wellhead design and available ports without re-loading. U.S. Patent Application Publication No. 2014/0262302 to Ferguson et al. discloses a system of this nature. The balls are individually pumped directly into the frac head where high turbulence may damage the balls. As well, larger packer balls generally need to be launched from above the frac tree, making the launch more complicated.
Applicant's previously patented ball drop system is described in U.S. Pat. Nos. 8,256,514 and 8,561,684 to Winzer. The ball drop system includes a vertically stacked manifold 40 of pre-loaded balls oriented in a vertical stack in a bore which is axially aligned above the main axial passageway of the frac head. Each ball is temporarily supported in the bore by a rod. Each rod is sequentially actuated to withdraw from the bore when required to release or launch the next largest ball. The lowest ball (closest to the wellbore of the wellhead) is typically the smallest ball, although same sized balls may be loaded.
U.S. Patent Publication No. 2014/0360720 to Corbeil describes a ball drop system mounted above a wellhead assembly. The balls are loaded in a vertical stack in an manifold, with each ball temporarily supported on a hinged pin for sequential dropping into the bore of the wellhead assembly. The wellhead assembly includes ball launch valves above and below a staging assembly to allow the balls to be sequentially dropped into the wellhead located therebelow, while maintaining the ball injector at atmospheric pressure.
In the above systems, if a ball is damaged or disintegrates upon arrival at the downhole tool, a replacement ball or one of the same diameter must be reloaded and launched again. If the ball drop system is pressurized, as it is for most of the prior art systems, the entire apparatus must be depressurized, removed and reloaded to get a smaller ball under the remaining loaded balls. Due to the size, weight and height of these systems, this is a time consuming and costly process, and must be carefully managed to maintain safe control in a hazardous environment and to complete testing and re-pressurization procedures upon reinstallation to the wellhead. The Corbeil system includes further wellhead valves and staging equipment in the vertical stack above the wellhead, adding height and safety concerns as mentioned above, as well as still requiring individual ball launch mechanisms to be provided and engaged for each individual ball, adding to costs and the possibility of an unsuccessful ball launch.
It is also important to note that the fracturing operations involve a large number of trucks, pumps, containers, hoses or other conduits, and other equipment for a fracturing system. In practice, many trucks and pumps are used to provide the cumulative amounts of fluid for the well at a well site which are moved from well to well. The difficulty of working around the wells with the large number of components also causes safety issues. The number of assembled equipment components raises the complexity of the system and the ability to operate in and around the multiple wells. Improvements are needed in a ball launch system to simplify the complexity of the system at the frac head. There remains a need for a safe, efficient and remotely operated apparatus to introducing balls to a wellbore.